NESHAP Area Source Boiler Energy Assessment Report. University of Minnesota Crookston Campus Coal fired Boiler #4

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1 NESHAP Area Source Boiler Energy Assessment Report University of Minnesota Crookston Campus Coal fired Boiler #4 November 11, 2014 Prepared By: Jared Satrom, P.E. Senior Mechanical Engineer, U of M Reviewed By: Erick VanMeter, Associate Director, U of M

2 Table of Contents: Section I: Executive Summary Section II: Energy Assessment Basic Requirements 1. Visual inspection of boiler 2. Boiler operations evaluation 3. Boiler energy consumption inventory 4. Boiler documentation review 5. Energy conservation opportunities 6. Energy conservation potential 7. Energy efficiency upgrade plans Section III: Detailed Boiler Energy Analysis Methodology Assumptions Results Section IV: Efficiency Improvement Opportunities Appendix A: Boiler 4 Energy Balance Diagram Appendix B: Boiler 4 Energy Balance Calculations Appendix C: Boiler 4 Photos Appendix D: Detroit Stoker Company Service Report (03/15/14) Page 2 of 26

3 Section I: Executive Summary During the heating season, University of Minnesota Twin Cities (UMTC) staff as well as University of Minnesota Crookston (UMC) staff conducted several site meetings and investigations to gather information in accordance with the requirements of the National Emission Standard for Hazardous Air Pollutants (NESHAP) for Area Sources, 40 CFR Part 53 Subpart 6J. This report serves to document these findings and fulfill the requirements outlined for the NESHAP Energy Assessment. The scope of this Energy Assessment includes the main coal fired Boiler #4 and auxiliary systems within the main boiler plant. The Assessment does not include the backup natural gas Boiler #5 nor any of its dedicated subsystems. In general, Boiler #4 is in good working order and currently operates at the lower end of industrystandard efficiencies (average Boiler 4 efficiency is about 75%). Some energy saving opportunities have been utilized already, including the installation of VFDs on all large prime movers (induced and forced draft fans), and the use of modern combustion controls including suitable DDC control loops that follow pre programmed turndown curves. Due to the inherent design (stoker style) and significant operating hours at part load, there is little room to reduce excess combustion air any further without either causing reliability issues or exceeding CO emission limits. Possible energy efficiency upgrades include improved insulation of the boiler, insulation of exposed steam piping, pre heating makeup water, and repairs of leaks in condensate return system. Page 3 of 26

4 Section II: Basic Energy Assessment Requirements (Reference: 13.pdf) The energy assessment must include the following 7 items: 1. A visual inspection of the boiler system (e.g. cracks, corrosion, leaks, insulation); a. Main coal boiler could be better insulated. Lower water wall headers specifically. b. Insulation missing on some distribution piping in tunnels (LF TBD, see photos) c. All major boiler problems (broken tubes, etc.) are dealt with promptly and root causes identified and corrected. Boiler is in sound, functional condition. 2. An evaluation of operating characteristics of the affected boiler systems, specifications of energy use systems, operating and maintenance procedures, and unusual operating constraints; a. See section below for detailed evaluation of plant efficiency. Items of note include excess air evaluation, identified leaks in condensate return system, identified areas of uninsulated steam and condensate piping. No unusual operating constraints exist on this boiler and in general all boiler systems are designed and operating efficiently. Due to boiler size and turndown required to meet average steam loads (approximately 2:1 on average) the boiler efficiency is somewhat reduced due to the requirement of higher combustion airflow rates. 3. An inventory of major systems consuming energy (i.e., energy use systems) from affected boiler(s) and which are under the control of the boiler owner or operator; a. All major systems consuming energy, besides the customer steam loads, are under the control of the boiler owner/operator see Section III below for detailed evaluation of plant efficiency. b. The boiler is approximately 75% efficient at converting fuel into gross steam output, while the plant ranges from 50% efficient to 65% efficient at producing steam for the customer. These efficiencies, while on the low end of industry standards, are primarily a result of the boiler consistently being operated at 2:1 or greater turndown. c. All combustion and flue gas fans are operating on variable frequency drives (VFDs) and controlled to follow pre set load curves. d. The boiler feed pump is powered with a small back pressure turbine which has an outlet steam pressure that matches the distribution pressure. e. The boiler air heater provides significant energy savings but could still benefit from more detailed measurements and optimization, as well as routine cleaning. f. The boiler pre heater setpoint was recently reduced as a result of the Detroit Stoker tuning during Spring Page 4 of 26

5 4. A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage; a. Review performed as part of boiler 4 energy balance and efficiency calculation. No unusual findings recorded after review of arch. and engineering plans. O&M procedures, logs, and fuel usage were kept on site at the facility, and logs and fuel usage data are incorporated in the detailed evaluation of plant efficiency. 5. A list of major energy conservation measures that are within the facility s control; a. Possibility to improve air heater performance with more frequent cleaning. b. Enhanced insulation of boiler. c. Insulation of all exposed piping within plant (steam and condensate) d. Improving condensate return (reducing condensate losses). e. Preheat makeup water using waste heat stream (boiler blowdown). f. Additional efficiency improvements require additional instrumentation, monitoring, and trending. Identify key points where additional measurements could be taken. See Assumptions in Section III below. 6. A list of the energy savings potential of the energy conservation measures identified; and a. Air heater performance improvement savings requires air flowrate measurements. But for purposes of discussion, 5% additional energy recovery is assumed. See Section IV for calculations (typ). b. Boiler insulation improvement estimated to reduce radiant losses from 2% to 1.5%. c. Piping insulation savings calculated in spreadsheet in Section IV below. d. Condensate return losses assumed to be reduced by 25%, and 20% reduction in horsepower assumed on condensate return pump. Savings calculated in Section IV below. e. Makeup water assumed to be pre heated from 40 deg F to 180 deg F. 7. A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments. a. See Section IV. Page 5 of 26

6 Section III: Detailed Boiler Energy Analysis Methodology In order to determine approximate boiler efficiency and operating cost, a full energy balance was required. Due to several missing inputs, several assumptions were made, as documented below. Standard mass and energy balances were conducted, both at the sub system boundary level (i.e. preheater, deaerator, etc) as well as the plant boundary level at various boiler loads. Due to the amount of assumptions required, the only inputs and outputs that were varied at different boiler loads were coal flow and steam flow. Combustion airflow was calculated based on coal flow, assuming the plant controls varied fan speeds accordingly to maintain approximately 13% excess oxygen in the flue gas stream. Inputs for the energy and mass balances were obtained from a combination of sources, primarily from daily steam plant logs, staff taking readings at average steam loads (documented in the Variables listing in Appendix A), or from the Detroit Stoker Company Service Report on 3/15/14 (Appendix D). Two efficiencies were calculated: 1) Gross Boiler Efficiency and 2) Plant Efficiency. The Boiler Efficiency was a simple calculation including only gross steam output BTUs per hour divided by the sum of coal + feedwater BTUs per hour. This efficiency remained constant at about 75% even as the boiler load was varied between 20% and 75% load. This highly consistent result is due to the assumption that coal consumption is directly proportional to steam output. This assumption had to be made because there was no accurate means by which coal flow could be measured at various boiler loads. Plant Efficiency was calculated based on net steam output to campus divided by total plant energy consumption, including parasitic loads such as fans and pumps. This efficiency varied from 50% to 65% as the boiler load increased from 20% to 75% load. Assumptions As mentioned above, several significant assumptions were required in order to complete the boiler and plant energy balance. For an exhaustive list of all inputs please refer to the Variables listing in Appendix A as well as Appendix B. Detailed discussion here will be reserved for the major assumptions that had a large impact on the results, while minor assumptions (such as mass flowrate of coal fly ash in the flue gas stream) will not be discussed. The reader can determine the acceptability of the more minor assumptions by reviewing the calculations found in Appendix B. As discussed in the methodology section, one of the most significant assumptions required for this analysis included the coal flow at various boiler load points. This was due to problems experienced with the plant coal scale, rendering daily coal consumption data inaccurate and unusable. Instead, monthly coal consumption data was determined based upon monthly coal purchases which were weighed using a calibrated scale. Another significant set of assumptions were required on the airside of the boiler. The Detroit Stoker boiler report did not include temperature measurements of combustion air entering the boiler (variable 9.1) nor the pre heater inlet temp (var. 9.9), therefore the energy balance assumed all airside Page 6 of 26

7 temperatures remained constant even at various boiler loads, and these temperatures were obtained from plant personnel while the boiler was at approximately 32% load. The last significant assumption was that the boiler experiences 2% radiant heat loss, which was based on industry standard assumptions. It is the suggestion of UMTC that additional temperature and flow measurements are taken if a more detailed energy balance is desired. These measurements would need to be taken at multiple boiler load points. The easiest and most informative additional measurements would be: Hourly coal consumption (var. 5.1) Pre Heater Inlet Temp (variable 9.9 in Appendix A) Pre Heater Outlet Temp (var. 9.7) Air Heater Flue Gas Inlet Temp (var. 9.3) Air Heater Flue Gas Outlet Temp (var. 9.11) Boiler Combustion Air Inlet Temp (var. 9.1) Overfire Air Inlet Temp (var 9.5) Additional measurements involving more effort/cost include: Steam flow to campus (var. 17) Condensate return flow (var. 25.1) Forced Draft Fan volumetric flow (var. 9.9) Overfire Air Fan volumetric flow (var. 9.5) Induced Draft Fan volumetric flow (var. 9.11) Results As discussed above and shown in the figures below, boiler efficiency remains largely constant at various loads ranging from 20% to 75% design steam flow. Plant efficiency gradually improves from 50% efficient at 20% design steam flow, up to 65% efficient at 75% design steam flow. Operating costs range from $18/1000 lbs steam at 20% design steam flow down to $8.62/1000 lbs steam at 75% design steam flow. Lastly, since average boiler load throughout the heating season is about 30%, the average annual cost for total plant energy input is $9.09/Mbtu. This cost is then used to calculate potential savings in Section IV below. Page 7 of 26

8 Figure 1: Boiler 4 Efficiency Figure 2: Boiler 4 Operating Costs Operating Costs of Boiler 4 (in $/1000 lbs or $/MBtu) $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $ 0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0% 70.0% 80.0% Boiler Load (out of 25 KPPH) Fuel $/1000 Lb Delivered Steam Total plant energy input cost per steam Mbtu Fuel cost per steam MBtu Page 8 of 26

9 Section IV: Efficiency Improvement Opportunities As listed in Section II above, the following efficiency improvement opportunities were identified, and are calculated in further detail below: 1. Air heater efficiency improved with deep cleaning: 5% additional energy recovery is assumed. a. At average boiler load of 32%, this results in a flue gas energy content reduction of 5%, with an assumed cost of $5,000. b. Approximate savings of $3,356/yr results in simple payback of 1.5 years. 2. Boiler insulation improvement estimated to reduce radiant losses from 2% to 1.5%. a. At average boiler load of 32%, this results in a 25% reduction in radiant losses. b. Approximate savings of $1,682/yr results in a simple payback of 3 years. 3. Piping insulation savings calculated in spreadsheet below. 4. Condensate return losses assumed to be reduced by 25% and 20% reduction in horsepower assumed on condensate return pump. Savings calculated below. a. Condensate return losses reduced by 25 kbtu/hr, $609/yr savings, 8.2 yr payback. b. Condensate pump power reduction of 20% results in electric savings of $190/yr, 26.4 yr payback 5. Makeup water pre heated from 40 deg F to 105 deg F using bolier blowdown a. Resulted in recovering 67 kbtu/hr from blowdown waste stream. b. Calculation was based upon the assumption that the use of a shell and tube heat exchanger could achieve a 5 degree F approach temp between leaving boiler blowdown and leaving makeup temps. c. Approximately $10,000 was budgeted to complete the installation. d. Approximate savings of $1,658/yr resulted in a simple payback of 6 years. Figure 3: Efficiency Improvement Opportunities Eff. Imp. Opp. # Item No. Description Improvement Amount (%) Units Before After Btu Savings $/Hr Savings $/Yr Improvement Savings Cost Simple Payback (yrs) Air Heater Deep Clean 5 Btu/hr 2,700,803 2,565, ,040 $ 0.66 $ 3,356 $5, Boiler Insulation Improvements 25 btu/hr 270, ,003 67,668 $ 0.33 $ 1,682 $5, N/A Piping Insulation Improvements 0 $ $ #DIV/0! Condensate return loss reduction 25 Btu/hr 98,062 73,546 24,515 $ 0.12 $ 609 $5, Condensate vac. pump elect. reduction 20 Btu/hr 38,175 30,540 7,635 $ 0.04 $ 190 $5, Pre heat makeup water 1307 Btu/hr 5,528 72,259 66,731 $ 0.33 $ 1,658 $10, Page 9 of 26

10 Appendix A: Boiler 4 Energy Balance Diagram Figure 4: Boiler #4 Mass and Energy Balance Diagram Note: This table uses Annual Data to determine average coal and steam flow Var. # Variable Needed Var. Units Notes, Quantity, or Answer 1 Makeup Water gpm 1.38 gpm 2 Type of delivered coal n/a Powder River Basin 3 Energy content of delivered coal btu/lb Cost of delivered coal $/ton $70.20 until 8/14, 9/14 onward $ Coal Flow lb/hr Bottom Ash lb/hr Fly Ash lb/hr 22 6 Type of oxygen measurement instrument n/a Wet Analyzer 7 % oxygen in flue gas % 13% average 8 Target excess combustion air % 100% load, <25% load 9.1 FD Combustion Air lb/hr 11, Combustion Air T - downstream of air heater deg F Flue Gas Upstream Air Heater deg F Flue Gas Upstream Air Heater lb/hr 16, Overfire Air deg F Overfire Air lb/hr 3, Pre-Heater Airside Outlet deg F Pre-Heater Airside Outlet lb/hr 11, Pre-Heater Airside Inlet deg F Pre-Heater Airside Inlet lb/hr 11, Air Heater Flue Gas Outlet lb/hr 16, Air Heater Flue Gas Outlet deg F ID fan rated power HP RPM 9.13 FD fan rated power HP RPM 9.14 Overfire Air Fan Rated Power HP RPM 11.1 Boiler Feedwater deg F sat DA outlet, 220 deg BFWP inlet 11.1 Boiler Feedwater lb/hr 7, Boiler feed pump waterside discharge psig psig depending on waterside valve position 11.2 Boiler feed pump waterside suction psig 10 head + ~5 psig ==> NPSHA =~9.33 psig 14.1 Boiler Steam Gross Output deg F Sat. 125 psig (353 deg F) 14.1 Boiler Steam Gross Output psig 125 psig (saturated) 14.1 Boiler Steam Gross Output lb/hr Net Steam Output to Campus deg F ~350F (assuming 125 psig sat upstream of PRVs) 17 Net Steam Output to Campus psig 40 psig 17 Net Steam Output to Campus lb/hr 7, Steam Driven - Boiler feed pump curve n/a Coppus RL 16L 19 Steam Driven - Boiler feed pump power HP rpm 20.1 BFP Steam Inlet lb/hr 2, BFP Steam Outlet lb/hr 2, Steam to DA lb/hr Boiler Blowdown deg F 353 deg F 125 psig) 24.1 Boiler Blowdown psig 125 psig 24.1 Boiler Blowdown lb/hr Condensate Return lb/hr 6, Electric - Cond. Vac. Pump HP 5 HP VAC +10 HP CND pump = 15 HP 26 Condensate Vacuum Pump Outlet Pressure psig ~4.5 psig, 3.5 psig DA 27 Condensate Return Losses lb/hr Condensate return temp. deg F Radiant Losses btu/hr 45, DA Vent btu/hr 19, Pre-Heater Steam Inlet btu/hr 359, Pre-Heater Cond. Outlet btu/hr 48,547 Page 10 of 26

11 Appendix B: Boiler 4 Energy Balance Calculations Item No. Energy Flow Summary Total Btus Comments % Source Fuel $/Coal Coal MMBTU Boiler Inputs 13,533,505 Should equal "Boiler Outputs" 93.7% Boiler Outputs 13,978,043 Should equal "Boiler Inputs" 95.1% Net Steam Output to Campus 8,293, % Parasitic Losses 3,740, % Plant Boundary Inputs 12,583, % Plant Boundary Outputs 11,460, % Plant Boundary Inputs Outputs 1,122,891 Should be 100% (Gross Steam Out)/(Coal + BFW In) 75% Boiler Efficiency (modern 81 83% $/hr Source Fuel Coal % Source Fuel Electric $/Elect. MMBTU $/hr Source Fuel (Elect) Total $/hr $ $ % $ $ $ $ $ % $ $ $ $ $ % $ $ $ $ $ % $ $ 2.09 $ $ $ % $ $ 3.28 $ $ $ % $ $ $ Boiler Energy Balance % $/ton of coal Btu of 1 ton coal $/Coal MMBTU $ $ Plant Bound. Outputs/Inputs 91% $/kwh kwh/btu $/Elect. MMBTU Net Steam / Plant Bound. Inputs 66% Plant Efficiency (modern 72 77%) $ $ Fuel $/1000 Lb Delivered Steam $ 6.72 "Variable" cost, not fully loaded Fuel cost per MBtu $ 4.53 Incl. coal only Total energy input cost / Mbtu $ 4.87 Incl coal & elec. Boiler Inputs Mass Temp Enthalpy Q in % of Total Unit (deg F) (btu/lb) (btu/hr) Input (lb/hr) Notes 5.1 Coal Flow lb/hr 1,120 n/a 1,120 9,469 10,604, % Gross specific heat content, including moisture. 9.1 FD Combustion Air lb/hr 20, , ,245, % 9.5 Overfire Air lb/hr 6, , , % 11.1 Boiler Feedwater gpm , ,528, % Total 13,533, % Item No. Boiler Outputs Unit Temp (deg F) Mass (lb/hr) enthalpy (btu/lb) Q out (btu/hr) % of Total Output 9.3 Flue Gas Upstream Air Heater lb/hr 29, , ,158, % 5.2 Bottom Ash lb/hr , % 5.3 Fly Ash lb/hr , % 14.1 Boiler Steam Gross Output lb/hr 7, ,939 1,193 9,470, % 24.1 Boiler Blowdown gpm ,193 73, % 29.1 Radiant Losses btu/hr 270,670 n/a n/a n/a 270, % Assume 2% loss Total 13,978, % Item No. Intermediate Plant Inputs (Subsystem Energy Flows) Unit Temp (deg F) Mass (lb/hr) enthalpy (btu/lb) Q in (btu/hr) % of Total Input 1.1 Makeup Water gpm , % 9.7 Pre Heater Airside Outlet lb/hr 20, , ,245, % 9.9 Pre Heater Airside Inlet lb/hr 20, , , % 20.2 BFP Steam Outlet lb/hr 2, , ,151, % 45 psig output 25.1 Condensate Return lb/hr 6, , , % 31.2 Pre Heater Cond. Outlet lb/hr , % Page 11 of 26

12 Appendix B: Boiler 4 Energy Balance Calculations (contd) Item No. Intermediate Plant Outputs (Subsystem Energy Flows) Unit Temp (deg F) Mass (lb/hr) enthalpy (btu/lb) Q out (btu/hr) % of Total Output 9.11 Air Heater Flue Gas Outlet Btu/hr 2,700, , ,700, % 17 Net Steam Output to Campus lb/hr 6, ,866 1,208 8,293, % BFP Steam Inlet HP ,677 1,193 3,193, % Coppus turbine pump 21.1 Steam to DA lb/hr , % 31.1 Pre Heater Steam Inlet lb/hr , , % Item No. Plant Boundary Inputs Unit Temp (deg F) Mass (lb/hr) enthalpy (btu/lb) Q in (btu/hr) % of Total Input 1.1 Makeup Water gpm , % 5.1 Coal Flow lb/hr 1,120 n/a 1,120 9,469 10,604, % 9.5 Overfire Air lb/hr 6, , , % 9.9 Pre Heater Airside Inlet lb/hr 20, , , % 9.12 Electric ID Fan HP 20 n/a n/a n/a 50, % 9.13 Electric FD Fan HP 10 n/a n/a n/a 25, % 9.14 Electric OFA Fan HP 10 n/a n/a n/a 25, % 25.1 Condensate Return lb/hr 6, , , % 26 Electric Cond. Vac. Pump HP 15 n/a n/a n/a 38, % Electric Inputs Sub Total 139, % Non Electric Inputs Sub Total 12,443, % Total 12,583, % Item No. Plant Boundary Outputs Unit Temp (deg F) Mass (lb/hr) enthalpy (btu/lb) Q out (btu/hr) % of Total Output 5.2 Bottom Ash lb/hr , % 5.3 Fly Ash lb/hr , % 9.11 Air Heater Flue Gas Outlet Btu/hr 2,700, , ,700, % 17 Net Steam Output to Campus lb/hr 6, ,866 1,208 8,293, % 24.1 Boiler Blowdown gpm ,193 73, % 27 Condensate Return Losses gpm n/a , % 29.1 Boiler Radiant Losses btu/hr 270,670 n/a n/a n/a 270, % 30 DA Vent lb/hr ,155 19, % Total 11,460, % Page 12 of 26

13 Appendix B: Boiler 4 Energy Balance Calculations (contd) Item No. Parasitic Losses Unit Temp (deg F) Mass (lb/hr) enthalpy (btu/lb) Q loss (btu/hr) % of Total Output 5.2 Bottom Ash lb/hr , % 5.3 Fly Ash lb/hr , % 9.11 Air Heater Flue Gas Outlet Btu/hr 2,700, , ,700, % 9.12 Electric ID Fan HP 20 n/a n/a n/a 50, % RPM 9.13 Electric FD Fan HP 10 n/a n/a n/a 25, % RPM 9.14 Electric OFA Fan HP 10 n/a n/a n/a 25, % RPM 20 BFP Net Energy ( ) btu/hr 41,219 n/a n/a n/a 41, % 24.1 Boiler Blowdown gpm , % Assume 2% loss 29.1 Boiler Radiant Losses btu/hr 270,670 n/a n/a n/a 270, % 26 Electric Cond. Vac. Pump HP 15 n/a n/a n/a 38, % Assuming 100% power 27 Condensate Return Losses gpm n/a , % must add to dist. Loss and blowdown = makeup 30 DA Vent lb/hr ,155 19, % Assuming 3/16" 3.5 psig 0 psig X.2 Evap of Hydrogen Formed Water lb/hr % Assume zero, no H2 monitoring. X.3 Evap of Fuel Moisture lb/hr , , % X.4 Water Vapor in Combustion Air lb/hr ,300 28, % X.6 Electric Misc. Plant Loads kw 0 n/a n/a n/a 0.00% Total 3,740, % Notes 1. "Item No." first digit corresponds to the first digit in the "Required Inputs" Google doc. The second digit is a sequence number that does not correlate with the google 2. Using Winter operating data. Where applicable, using annually averaged data (i.e. XX lb/hr is the average over winter '12 '13) 3. Q in = Q out Q loss 4. Average OAT: 16 deg F. Average RH of 84%. ==> average moisture content: lb H20/lb air ==> assume dry outside air 5. Average Coal moisture content: 25% per 2013 test results. Assume coal temp is 32 deg. 6. Average flue gas O2 taken from , breeching of boiler. 7. Reference for O2 and flue gas analysis: h/chapters/fluegas.html 8. Assume overfire airflow is equal to FD airflow. 9. Specific Heat of flue gas calculated using performance.com/calc flue gas prop.html Page 13 of 26

14 Appendix B: Boiler 4 Energy Balance Calculations (contd) unknown ṁ BBdwn = Boiler Waterside Governing Equations 0 = ṁ CNDRet + ṁ DAstm + ṁ MUw ṁ BFWPout ṁ BBdwn ṁ Distloss ṁ DAvent 0 = ṁ MUw ṁ BBdwn ṁ Distloss ṁ DAVent 0.10 * ṁ Distloss knowns: ṁ STM = 7,939 lb/hr ṁ MUw = 691 lb/hr ṁ Distloss = 613 ṁ BBdwn = 61 lb/hr ==> 0 = ṁ MUw 1/3(ṁ Distloss ) ṁ Distloss ṁ DAVent 0 = Q CNDRet + Q DAstm + Q MUw (Q BFWPSin Q BFWPSout ) Q DAvent Q STMCampus =Q 14.1 Q 31.1 Q Q 20.2 Q 21 = DA Mass Balance Var. No. DA Mass Flow In (ṁ) Eqn. Name (lb/hr) Notes 25.2 Condensate Return ṁcond 6, DA Steam ṁdastm 558 1Makeup Water ṁmuw 691 Total 7,956 Var. No. DA Mass Flow Out (ṁ) (lb/hr) 11.1 Boiler Feedwater ṁbfwpout 7, DA Vent ṁdavent /16" 4 psig sat steam, flow r Total 7,956 Boiler Mass Balance Var. No. Boiler Mass Flow In (ṁ) Eqn. Name (lb/hr) Notes 11.1 Boiler Feedwater ṁbfwpout 8,000 Total 8,000 Var. No. Boiler Mass Flow Out (ṁ) (lb/hr) 14.1 Gross Steam Output ṁstm 7, Boiler Blowdown ṁbbdwn 61 Total 8,000 Plant Mass Balance Var. No. Plant Mass Flow In (ṁ) Eqn. Name (lb/hr) Notes 1Makeup Water ṁmuw 691 Var. No. Boiler Mass Flow Out (ṁ) (lb/hr) 24 Boiler Blowdown ṁbbdwn Cond/Steam Loss ṁdistloss DA Vent ṁdavent 17 Total 691 DA Energy Balance Var. No. DA Energy Flow In (Q ) Eqn. Name (Btu/hr) Notes 25.2 Condensate Return Q CNDret 992, DA Steam Q DAstm 512,343 1Makeup Water Q MUw 5,528 Total 1,510,512 Var. No. DA Energy Flow Out (Q ) (Btu/hr) 11.1 Boiler Feedwater Q BFWPout 1,528, DA Vent Q Davent 19,409 Total 1,547,409 Boiler Waterside Energy Balance Var. No. Boiler Waterside Energy Flow In (Q Eqn. Name (Btu/hr) Notes 1Makeup Water Q MUw 5, Boiler Feedwater Q BFWPout 1,528,000 Total 1,533,528 Var. No. Boiler Waterside Energy Flow Out (Q ) (Btu/hr) 14.1 Gross Steam Output Q STM 9,470, Boiler Blowdown Q BBdwn 73, Condensate Loss Q distloss 98,062 Assume 100% losses on condensate side, 0% steam side 30 DA Vent Q DAvent 19,409 Total 9,661,471 Delta 8,127,943 Boiler Airside Governing Equations 0 = ṁ Coal + ṁ OFAir + ṁ FDAir ṁ BtmAsh ṁ FlyAsh ṁ FG 0 = ṁ PHOAin ṁ PHOAout 0 = Q PHOAin + Q PHSTMin Q PHOAout Q PHSTMout Var. No. Pre Heater Mass OA Flow In (ṁ) Eqn. Name (lb/hr) Notes 9.9 Pre Heater OA Inlet (Dry) ṁ PHOAinD 20,752 Average OAT: 16 deg F. Average RH of 84%. ==> average moisture content: lb H20/lb air ==> 31.1 Pre Heater Steam Inlet ṁ PHSTMin 523 lb/hr due to airside energy gain/enthalpy change Total 21,275 Var. No. Pre Heater Mass OA Flow Out (ṁ) Eqn. Name (lb/hr) 9.7 Pre Heater OA Outlet (Dry) ṁ PHOAoutD 20, Pre Heater Steam Outlet ṁ PHSTMout 523 Total 21,275 Var. No. Pre Heater Energy Flow In (Q ) Eqn. Name (Btu/hr) Notes 9.9 Pre Heater OA Inlet Q PHOAinD 498, deg inlet, enthalpy 24 btu/lb dry 10 grains /lb moisture 31.1 Pre Heater Steam Inlet Q PHSTMin 623, psig sat steam, 1193 btu/lb total heat Total 1,121,787 Var. No. Pre Heater Energy Flow Out (Q ) Eqn. Name (Btu/hr) Notes 9.7 Pre Heater OA Outlet (Dry) Q PHOAoutD 1,037, deg outlet, enthalpy 50 btu/lb dry air, assumed constant 31.2 Pre Heater Steam Outlet Q PHSTMout 84, psia, 161 btu/lb total heat Total 1,121,787 Delta 0 Airside Energy Gain 539,558 Equal to steam energy loss ( = 1032 btu/lb ==> ṁ Var. No. Air Heater Mass Flow In (ṁ) Eqn. Name (lb/hr) Notes 9.7 Pre Heater OA Outlet ṁ PHOAoutD 20, Air Heater Flue Gas Inlet ṁ AHFGin 29,296 Total 50,048 Var. No. Air Heater Mass Flow Out (ṁ) Eqn. Name (lb/hr) 9.1 Air Heater OA Outlet ṁ AHOAout 20, Air Heater Flue Gas Outlet ṁ AHFGout 29,296 Total 50,048 Delta 0 Pre Heater Mass Balance Pre Heater Energy Balance Air Heater Mass Balance Air Heater Energy Balance Var. No. Air Heater Energy Flow In (Q ) Eqn. Name (Btu/hr) Notes 9.7 Pre Heater OA Outlet Q PHOAoutD 1,037, deg outlet, enthalpy 50 btu/lb dry air, assumed constant 9.3 Air Heater Flue Gas Inlet Q AHFGin 3,017, deg outlet of boiler, enthalpy = 103 Btu/lb, assumed constant Total 4,055,105 Var. No. Air Heater Energy Flow Out (Q ) Eqn. Name (Btu/hr) Notes 9.1 Air Heater OA Outlet Q AHOAout 1,760, deg outlet, enthalpy = Btu/lb, assumed constant due to lack of data 9.11 Air Heater Flue Gas Outlet Q AHFGout 2,700, deg outlet, enthalpy = Btu/lb, assumed constant due to lack of data Total 4,461,422 Delta 406,317 FD Energy Gain 723,008 FG Energy Loss 316,690 Air Heater Effectiveness 228% (FD Gain/FG Loss), remaining 66% in radiant losses? FD leakage? Page 14 of 26

15 Appendix B: Boiler 4 Energy Balance Calculations (contd) ID Airflow Calc (based on combustion) Governing Equations 0 = ṁ FGTotal ṁ CoalH2O ṁ CoalH2 ṁ CoalFlyAsh ṁ FGCO + ṁ FGCO2 ṁ FGO2 Oxygen Mass Bal. 0 = ṁ TotalCombO2 ṁ FG02 ṁ OFADry02 + ṁ FGCombO2 Carbon Mass Bal. 0 = ṁ CoalC ṁ FGC02 ṁ FGCO Excess Coal Outside Air Combustion Mass Flows lb/hr Coal Analysis (% by weight) Net % free O2 by weight Net % free O2 by weight ṁ TotalCombAir = % Moisture ṁ TotalCombO2 = % of air is O2 by mass, assuming 0% CO creation, no excess air. % Carbon ṁ TotalCombN2 = % of air is Nitrogen/inert gases by mass % Hydrogen ṁ FDAir = Assume 75% combustion air is through forced draft fan % Nitrogen ṁ FD02 = 3203 % Chlorine ṁ OFAir = 6917 Assume 25% of combustion air is overfire air % Sulfur ṁ OFAir02 = 3203 % Ash ṁ Coal = 1120 Total coal flow % Oxygen ṁ Coal02 = 129 Free oxygen in coal, O2 molec weight = *2 Total Coal Oxygen (ṁ CoalO2 ) lb/hr 129 Total Air Oxygen (ṁ OAO2 ) lb/hr ṁ CoalC = 606 Carbon content of coal (54.14%), atm weight = ṁ CombO2 = 3102 Total O2 from combustion air reqd. for stoichiometric combustion Total Coal Carbon (ṁ CoalC ) lb/hr 606 ṁ CoalBtmAsh = 23 Assume 50% ash content becomes bottom ash (4.12%/2) Total OA Oxygen (ṁ OAO2 ) lb/hr ṁ CoalH20 = % Water content of coal (25.4%) ṁ CoalH2 = % Hydrogen content of coal (3.08%) ṁ CoalFlyAsh = % Assume 50% ash content becomes fly ash (4.12%/2) ṁ FGCO = % Carbon to CO, CO atom. weight = 14, 3000 ppm in FG ==> (0.003)ṁ FGTotal Notes ṁ FGCO2 = % Carbon to CO2, CO2 atom. weight = ṁ FGResO2 = % Amount of O2 not consumed during combustion, assuming no CO creation. ṁ FGN2 = % 76.85% of air is inert gas by mass ==> (0.7685)ṁ TotalCombAir Total Flue Gas = % ṁ TotalCombAir = Residual FG O2 avg 13% by mass, 23.15% of air is O2 by mass, => 10.15% of comb air is O2 f ṁ FGTotal = Combustion air mass flow plus coal mass flow. Page 15 of 26

16 Appendix C: Boiler 4 Photos Page 16 of 26